A total of 616 million barrels of contingent resources (best estimate) assigned to our 3 core properties with a BTNPV10 of $2.0 billion;

Our largest property is the Blackrod SAGD project with proved plus probable reserves of 181 million barrels and best estimate contingent resources of 566 million barrels of oil, with potential production reaching 80,000 barrels of oil per day;

Our Onion Lake thermal project was assigned proved reserves of 50 million barrels of oil and proved plus probable reserves of 85 million barrels, with peak production potential of 12,000 barrels of oil per day. An additional 32 million barrels of best estimate contingent resource was attributed to the Onion Lake thermal areas. The first 6,000 per day barrel phase of the Onion Lake thermal project is expected to be completed in mid-2015;

Q4 2014 production averaged 9,639 boe/day; full year production of 9,287 boe/day.

John Festival commenting on the 2014 reserves evaluation indicated that “over the last three years the potential of our three core properties began to be recognized in our independent reserves and contingent resource assessments. The net present value (discounted at 10%, BT) Sproule assigned to our proved reserves represents $2.93 per common share and on a proved plus probable basis the value represents $7.97 per share. The value Sproule has assigned to best estimate contingent resources represents an additional $5.32 per share.

Our objective going forward is to convert this potential into production and cash flow. We took a big step forward in that regard in 2014 with the commencement of construction of the first phase of the Onion Lake thermal EOR project.”

Oil and Gas Reserves

The following tables summarize certain information contained in the independent reserves report prepared by Sproule Unconventional Limited (“Sproule”) as of December 31, 2014. The report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form which will be filed on SEDAR on or before March 31, 2015. It should not be assumed that the net present value of reserves estimated by Sproule represents the fair market value of these reserves.

Summary of Oil and Gas Reserves

(Company interest, before royalties)

Heavy Oil

Bitumen

Total
Crude Oil

Natural
Gas

2014
Total

2013
Total

(Mbbl)

(Mbbl)

(Mbbl)

(MMcf)

(MBoe)

(MBoe)

Proved developed producing

7,416

1,309

8,725

299

8,766

8,826

Proved developed non-producing

2,107

0

2,107

43

2,114

2,205

Proved undeveloped

54,835

429

55,264

65

55,275

52,798

Total proved

64,358

1,739

66,097

407

66,165

63,829

Probable

50,947

179,456

230,403

319

230,456

226,777

Total proved plus probable

115,305

181,195

296,500

726

296,621

290,606

Notes:

(1)

BOE’s may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 Mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

(2)

Based on Sproule’s December 31, 2014 forecast prices

(3)

Columns may not add due to rounding

Net Present Value of Reserves

0%

5%

10%

15%

20%

($000)

Before Tax

Proved

Developed producing

207,776

183,390

164,207

148,784

136,152

Developed non-producing

76,455

58,381

45,453

35,995

28,936

Undeveloped

2,165,100

1,222,461

772,355

530,909

387,691

Total proved

2,449,330

1,464,231

982,015

715,688

552,779

Probable

7,607,464

3,373,789

1,691,518

920,130

525,568

Total proved plus probable

10,056,794

4,838,020

2,673,532

1,635,818

1,078,348

After Tax

Proved

Developed producing

207,776

183,390

164,207

148,784

136,152

Developed non-producing

76,455

58,381

45,453

35,995

28,936

Undeveloped

1,697,572

980,743

634,508

445,784

331,721

Total proved

1,981,802

1,222,514

844,168

630,563

496,809

Probable

5,672,610

2,472,061

1,208,087

632,787

341,412

Total proved plus probable

7,654,413

3,694,575

2,052,255

1,263,350

838,221

Notes:

(1) Based on Sproule’s December 31, 2014 forecast prices

(2) Columns may not add due to rounding

Estimated Future Development Capital

The following table summarizes the future development capital (“FDC”) Sproule estimates is required to bring the proved, and proved plus probable reserves on production.

($ Millions)

Total Proved

Total Proved + Probable

2015

61.5

62.7

2016

27.3

136.7

2017

22.8

130.6

2018

28.3

96.0

2019

28.1

352.7

Remainder

329.1

1,780.8

Total FDC undiscounted

497.1

2,559.5

Total FDC discounted at 10%

243.1

1,129.2

Reconciliation of Changes in Reserves

The following table summarizes the changes in the Company’s share of oil and natural gas reserves (before royalties) from December 31, 2013 to December 31, 2014.

Oil, Heavy Oil & Bitumen

Natural gas

BOE

Proved

Probable

Total

Proved

Probable

Total

Total

(Mbbls)

(Mbbls)

(Mbbls)

(MMcf)

(MMcf)

(MMcf)

(Mboe)

Balance, Dec 31, 2013

63,804

226,754

290,558

154

137

291

290,606

Production

(3,241)

0

(3,241)

(904)

0

(904)

(3,391)

Extensions

481

397

878

6

0

6

878

Discoveries

0

0

0

0

0

0

0

Technical revisions

5,075

3,241

8,316

1,161

173

1,334

8,538

Improved recovery

0

0

0

0

0

0

0

Acquisitions

0

0

0

0

0

0

0

Dispositions

0

0

0

0

0

0

0

Economic factors

(22)

11

(11)

(10)

10

0

(11)

Balance, Dec 31, 2014

66,097

230,403

296,500

407

319

726

296,621

Notes:

(1)

BOE’s may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 Mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

(2)

Columns may not add due to rounding

The pricing assumptions used in the Sproule evaluation are summarized below.

Pricing Assumptions

Year

WTI
Cushing
40&#176; API

Canadian Light Sweet Crude 40&#176; API

Western
Canadian Select
20.5&#176; API

Alberta
AECO-C
Spot

Inflation rate

Exchange rate

(US$/bbl)

(CDN$/bbl)

(CDN$/bbl)

(CDN$/MMBtu)

(%/yr)

(US$/Cdn$)

2015

65.00

70.35

60.50

3.32

1.5

0.85

2016

80.00

87.36

75.13

3.71

1.5

0.87

2017

90.00

98.28

84.52

3.90

1.5

0.87

2018

91.35

99.75

85.79

4.47

1.5

0.87

2019

92.72

101.25

87.07

5.05

1.5

0.87

2020

94.11

103.85

89.31

5.13

1.5

0.87

2021

95.52

105.40

90.65

5.22

1.5

0.87

2022

96.96

106.99

92.01

5.31

1.5

0.87

2023

98.41

108.59

93.39

5.40

1.5

0.87

2024

99.89

110.22

94.79

5.49

1.5

0.87

2025

101.38

111.87

96.21

5.58

1.5

0.87

Escalation rate of 1.5% thereafter

Notes:

(1)

The pricing assumptions were provided by Sproule Unconventional Limited

(2)

None of the Company’s future production is subject to a fixed or contractually committed price.

Definitions:

(a) “Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) “Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(c) “Developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

(d) “Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(e) “Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

(f) “Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

(g) The Net Present Value (NPV) is based on Sproule Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Sproule evaluations will be attained, and variances could be material.

Contingent Resources

The following table summarizes certain information contained in the contingent resource evaluations prepared by Sproule as of December 31, 2014. The reports were independently prepared in accordance with definitions, standards and procedures contained in the COGE Handbook.

It should not be assumed that the estimates of recovery, production, and net revenue presented in the tables below represent the fair market value of the Company’s contingent resources. There is no assurance that the forecast prices and cost assumptions will be realized and variances could be material. The recovery and production estimates of the Company’s contingent resources provided herein are only estimates and there is no guarantee that the estimated contingent resources will be recovered or produced. Actual contingent resources may be greater than or less than the estimates provided here. There are certain contingencies which currently prevent the classification of these contingent resources as reserves. Information on these contingencies is provided in the footnotes to the tables below. There is no certainty that it will be commercially viable for the Company to produce any portion of the contingent resources on any of its properties.

Net Present Values of Before Tax Future Net Revenue
as of December 31, 2014
Contingent Resources – Best Estimate
Discounted at

0%

5%

10%

15%

20%

(Mboe)

($000)

Blackrod

566,135

15,862,704

4,825,694

1,594,391

520,500

131,717

Onion Lake

33,512

1,444,215

611,407

292,335

154,221

87,368

Mooney

16,166

630,072

309,848

160,492

86,374

47,673

Total

615,813

17,936,991

5,746,949

2,047,218

761,095

266,758

Notes:

(1)

These volumes are arithmetic sums of multiple estimates of contingent resources, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of resources and appreciate the differing probabilities of recovery associated with each class as explained.

(2)

Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

(3)

There are three categories in evaluating contingent resources: Low Estimate, Best Estimate and High Estimate. Best estimate (P50) is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

(4)

The estimates of contingent resources (best estimate) and future net revenue for individual properties may not reflect the same confidence levels as estimates of contingent resources (best estimate) and future net revenues for all properties, due to the effects of aggregation.

(5)

“Gross” means the Company’s working interest share in the contingent resources of bitumen and heavy oil before deducting royalties. The Company has a 100% working interest at Blackrod and Mooney, and a 79.795 to 100% working interest at Onion Lake.

(6)

The amounts included in these tables do not include the volume and value of BlackPearl’s proved and probable reserves previously assigned by Sproule to these properties.

(7)

The contingencies in the Sproule Report associated with the Company’s Blackrod contingent resources are due to the following: (a)the requirement for more evaluation drilling, as required by the regulatory process, to define the reservoir characteristics to assist in the implementation and operation of the SAGD process (b)the absence of submission of an application to expand the commercial SAGD development; and (c)the uncertainty of timing of production and development.

(8)

The contingencies in the Sproule Report associated with the Company’s Onion Lake contingent resources are due to the following: (a)the absence of approval to extend the SAGD development area (b)the requirement for more evaluation drilling to define the reservoir characteristics of the resource to assist in the implementation and operation of the SAGD recovery process; (c)the uncertainty of company commitment for expansion of the commercial SAGD development; and (d)the uncertainty of timing of production and development.

(9)

The contingencies in the Sproule Report associated with the Company’s Mooney contingent resources are due to the following: (a) the requirement for more evaluation wells to further define reservoir and fluid characteristics; and (b)the uncertainty of timing of production and development of the entire field.

Production Update

BlackPearl’s Q4 2014 oil and gas sales volumes were 9,639 boe per day, a 4% increase over production during the third quarter. The increase in fourth quarter production is mainly attributable to additional primary development drilling at Onion Lake. At Onion Lake, we drilled 11 conventional wells during the third quarter which began to contribute to production in the fourth quarter.

Three months ended
December 31

Year ended
December 31

Production by Area (boe/d)

2014

2013

2014

2013

Onion Lake

4,651

5,186

4,263

4,797

Mooney

3,236

3,837

3,469

3,685

John Lake

1,109

1,066

1,067

898

Other

120

103

108

114

Blackrod

523

262

380

236

Total production

9,639

10,454

9,287

9,730

Other

The Company is planning to release its 2014 year-end financial and operating results on February 26, 2015.
At December 31, 2014, the Company had 335,638,226 common shares outstanding.

In particular, but without limiting the foregoing, this release contains forward-looking statements pertaining to, the volumes and estimated value of BlackPearl’s proved and probable reserves, the volumes and estimated value of BlackPearl’s contingent resources, potential production levels for the Blackrod SAGD project and the Onion Lake thermal project, the net present value per common share of our proved reserves, proved plus probable reserves and contingent resources and the estimate for future development capital.

The forward-looking information is based on expectations and assumptions by management regarding future production levels, future oil and natural gas prices, continuation of existing tax, royalty and regulatory regimes, foreign exchange rates, estimates of future operating costs, timing and amount of capital expenditures, performance of existing and future wells, the ability to obtain financing on acceptable terms, availability of skilled labour and drilling and related equipment, general economic and financial market conditions and the ability to market oil and natural gas successfully to current and new customers.

Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. Accordingly, undue reliance should not be placed on these forward-looking statements. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the differences may be material and adverse to the Company and its shareholders.

By their nature, forward-looking statements involve numerous known and unknown risks and uncertainties that contribute to the possibility that actual results will differ from those anticipated in the forward looking statements. These risks include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent, general economic, market and business conditions, volatility of commodity inputs, substantial capital requirements, customary conditions including receipt of necessary regulatory and stock exchange approvals on the issuance of common shares, uncertainties inherent in estimating quantities of reserves and resources, extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time, the need to obtain regulatory approvals on projects before development commences, environmental risks and hazards and the cost of compliance with environmental regulations, aboriginal claims, inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions, financial loss associated with derivative risk management contracts, potential cost overruns, variations in foreign exchange rates, variations in interest rates, diluent and water supply shortages, competition for capital, equipment, new leases, pipeline capacity and skilled personnel, uncertainties inherent in the SAGD bitumen and ASP recovery process, credit risks associated with counterparties, the failure of the Company or the holder of licences, leases and permits to meet requirements of such licences, leases and permits, reliance on third parties for pipelines and other infrastructure, changes in royalty regimes, failure to accurately estimate abandonment and reclamation costs, inaccurate estimates and assumptions by management, effectiveness of internal controls, the potential lack of available drilling equipment and other restrictions, failure to obtain or keep key personnel, title deficiencies with the Company’s assets, geo-political risks, risks that the Company does not have adequate insurance coverage, risk of litigation and risks arising from future acquisition activities. Readers are also cautioned that the foregoing list of factors is not exhaustive. Further information regarding these risk factors may be found under “Risk Factors” in the Annual Information Form.

The forward-looking statements contained in this release are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.